1. Field of the Invention
Aspects of the present invention generally relate to operating a downhole tool. Particularly, the present invention relates to apparatus and methods for remotely actuating a downhole tool. More particularly, the present invention relates to apparatus and methods for actuating a downhole tool based on a monitored wellbore condition.
2. Description of the Related Art
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation. A cementing operation is then conducted in order to fill the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. The well is then drilled to a second designated depth, and a second string of casing or liner, is run into the well. In the case of a liner, the liner is set at a depth such that the upper portion of the liner overlaps the lower portion of the first string of casing. The liner is then fixed or “hung” off of the existing casing. A casing, on the other hand, is hung off of the surface and disposed concentrically with the first string of casing. Afterwards, the casing or liner is also cemented. This process is typically repeated with additional casings or liners until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casings of an ever-decreasing diameter.
In the process of forming a wellbore, it is sometimes desirable to utilize various tripping devices. Tripping devices are typically dropped or released into the wellbore to operate a downhole tool. The tripping device usually lands in a seat of the downhole tool, thereby causing the downhole tool to operate in a predetermined manner. Examples of tripping devices, among others, include balls, plugs, and darts.
Tripping devices are commonly used during the cementing operations for a casing or liner. The cementing process typically involves the use of liner wiper plugs and drill-pipe darts. A liner wiper plug is typically located inside the top of a liner, and is lowered into the wellbore with the liner at the bottom of a working string. The liner wiper plug typically defines an elongated elastomeric body used to separate fluids pumped into a wellbore. The plug has radial wipers to contact and wipe the inside of the liner as the plug travels down the liner. The liner wiper plug has a cylindrical bore through it to allow passage of fluids.
Generally, the tripping device is released from a cementing head apparatus at the top of the wellbore. The cementing head typically includes a dart releasing apparatus, referred to sometimes as a plug-dropping container. Darts used during a cementing operation are held at the surface by the plug-dropping container. The plug-dropping container is incorporated into the cementing head above the wellbore.
After a sufficient volume of circulating fluid or cement has been placed into the wellbore, a drill pipe dart or pump-down plug is deployed. Using drilling mud, cement, or other displacement fluid, the dart is pumped into the working string. As the dart travels downhole, it seats against the liner wiper plug, closing off the internal bore through the liner wiper plug. Hydraulic pressure above the dart forces the dart and the wiper plug to dislodge from the bottom of the working string and to be pumped down the liner together. This forces the circulating fluid or cement that is ahead of the wiper plug and dart to travel down the liner and out into the liner annulus.
Another common component of a cementing head or other fluid circulation system is a ball dropping assembly for releasing a ball into the pipe string. The ball may be dropped for many purposes. For instance, the ball may be dropped onto a seat located in the wellbore to close off the wellbore. Sealing off the wellbore allows pressure to be built up to actuate a downhole tool such as a packer, a liner hanger, a running tool, or a valve. The ball may also be dropped to shear a pin to operate a downhole tool. Balls are also sometimes used in cementing operations to divert the flow of cement during staged cementing operations. Balls are also used to convert float equipment.
There are drawbacks to using tripping devices such as a ball. For instance, because the tripping device must travel or be held within the string or the cementing head, the diameter of the tripping device is dictated by the inner diameters of the running string or the cementing head. Since the tripping device is designed to land in the downhole tool, the inner diameter of the downhole tool is, in turn, limited by the size of the tripping device. Limitations on the bore size of the downhole tool are a drawback of the efficiency of the downhole tool. Downhole tools having a large inner diameter are preferred because of the greater ability to reduce surge pressure on the formation and prevent plugging of the tool with debris in the well fluids.
Another drawback of tripping devices is reliability. In some instances, the tripping device does not securely seat in the downhole tool. It has also been observed that the tripping device does not reach the downhole tool due to obstructions. In these cases, the downhole tool is not caused to perform the intended operation, thereby increasing down time and costs.
Furthermore, cementing tools generally employ mechanical or hydraulic activation methods and may not provide adequate feedback about wellbore conditions or cement placement. For many cementing tools, balls, darts, cones, or cylinders are dropped or pumped inside of the tubular to physically activate the tools. Cementing operations may be delayed as the tripping device descends into the wellbore. Also, pressure increases monitored on the surface are usually the only indication that a tool has been activated. No information is available to determine the tool's condition, position, or proper operation. In addition, the location of the cement slurry is not positively known. The cement slurry position is typically an estimate based on volume calculations. Currently, no feedback is provided regarding cement height or placement in the annulus other than pressure indications.
There is a need, therefore, for an apparatus and method for remotely actuating a downhole tool. Further, there is a need for an apparatus and method to remotely actuate a float valve. The need also exists for an apparatus and method for actuating a centralizer. There is also a need for an apparatus and method for monitoring downhole conditions while running casing or cementing. There is a need still for an apparatus and method for determining cement location in a wellbore.